In hydrocarbon wells used for the production of hydrocarbons from reservoirs, a gas-lift technique is a widely used artificial lift technique to produce oil and gas from wells. In a typical hydrocarbon well operation, with time, the reservoir pressure reduces and liquids (i.e. oil, water and condensate) accumulate at the well bottom, which hinders natural flow of gas and liquids to the surface. A gas-lift method using gas injection in the hydrocarbon well is used to remove these liquids so that bottom-hole pressure reduces and flow from reservoir to the well-bottom takes place.
In particular, part of produced gas from the hydrocarbon production (that includes both gas and liquid), is compressed and re-injected to the well bottom via a mandrel system. In the mandrel system, mandrel acts as a valve between annulus and tubing, which allows gas flow. The resulting low density mixture of liquid and gas, (gas bubble in liquid or liquid droplets in gas), reduces the overall density of the mixture that leads to reducing the bottom-hole pressure of the well and allows the well to flow properly.
Production of liquid (e.g. oil) and gas, jointly being referred here as hydrocarbon, from such gas-lifted wells is a function of the rate of gas injection (injection choke opening), rate of production (production choke opening), depth at which gas is injected (mandrel position) as well as reservoir characteristics.
One class of methods for gas lift control presented in literature, involves regulation of the system to the desired operating condition by manipulating gas injection choke. These include either simple controller like PID (proportional-integral-derivative controller) or model-based controllers. The former does not take future dynamics and disturbances into account. The latter uses first principles model based approach, accuracy of which is highly depends on how detailed the model is and most of the time it is computationally intractable for real time control.
Another class of methods, aim at driving the well to an economic optimum (either maximizing profit or maximizing oil production). Herein, either first principles model are used, or statistical data-based models are built to obtain a generic production curve. Then the problem mainly reduces to operating at the optimal point, or using some gradient based method to move towards that point. Some such control approaches are available in the patent literature as listed below.
Patent document EP0756065A1 proposes production control of gas-lifted well using pressure variation based dynamic control (PID) via production and injection choke manipulation. Method for developing statistical model of well production behavior and its use for control is addressed in patent document EP1028227A1. A method for operating gas lift wells based on IPR (inflow performance relationship), curve and pressure vs. production rate relations (one for each parameter) based operating scheme is proposed in U.S. Pat. No. 4,442,710. The rule based production scheme based on ratio between gas injection and liquid production to maximize liquid production is addressed in U.S. Pat. No. 4,738,313 while rule based control based on comparison of optimal gas-lift slope with one variable is addressed in U.S. Pat. No. 5,871,048. Use of neural network based multi-phase flow regime model, which is trained using downhole data, to change gas injection rate is documented in U.S. Pat. No. 6,758,277B2. Various methods for optimal allocation of gas injection among multiple wells is addressed in U.S. Pat. No. 7,953,584B2 and US20080154564A1.
There is a need for a method that overcomes the challenge of addressing dynamic changes in the well operation for optimizing the hydrocarbon production quickly. The controllers (local computing devices) have less computational power to handle large operational data, and the turnaround time for control data from any central control system such as a supervisory control and data acquisition system (SCADA) to the controllers is very long due to communication protocols to handle the dynamic changes.
Further, from an operational viewpoint, maximum production from the hydrocarbon well is achieved when the operating valve, i.e. lower most mandrel valve (106), is open and unloading valves (107) are closed, as shown in FIG. 1. However, it is not always possible to operate with lowermost valve open. Due to various disturbances entering the system either from injection or line pressure, or from well irregularities, the continuous gas lift operation may be disturbed and open mandrel valve may change from operating valve to unloading valve.
As limited information/measurements are available in practice, which include surface measurements such as injection pressure, line pressure, tubing pressure and casing pressure, the knowledge of which mandrel valve is open is missing. In absence of direct measurement on mandrel valve operation, there is no accurate way to identify which valve is open or close. This presents the operating challenge on how much gas to inject via the gas injection choke and how to switch back to lowest mandrel operation via operation of production choke.
There are known methods to estimate flow regimes in tubing and model based approach for design of gas well unloading. These methods can primarily be used to improve design of unloading wells and does not deal with the operation of well. Several of the prior art methods use an inherent assumption that is the flow of annulus gas to the tubing is through the operating valve, i.e. lower most valve, and other valves (if any) remain closed. With this assumption, most of the state-of-the-art production models consider a single mandrel well.
Thus, these methods may not be applicable to the situation where the liquid loads up during dynamic well operation, as explained herein. During a gas lift start-up or manual unloading of the well, the operator typically uses heuristics based on best practice. API RP 11V5 standard details the required recommended practice for operation, maintenance, and troubleshooting gas lift installations. During the startup, the operating mandrel switch between different mandrels and when the operator assumes that optimal mandrel operation is reached, he or she operators operate the well in auto mode. This is done by injecting the gas in annulus to depreciate the liquid level in annulus and enabling the next lower mandrel valve to operate till the last operating valve is reached. This operation is also known as unloading well. Now, during the normal operation, if due to any disturbance, a switch of the operating mandrel from the lower most mandrel to an unloading mandrel happens, the hydrocarbon flow from the well is adversely affected leading to lower production and higher gas injection cost.
Besides, the above issues of controlling the gas injection choke and the production choke, identifying accurate unloading or operating valve, the control of gas lift operation in onshore unconventional fields (e.g., shale gas) presents some unique challenges due to reservoir characteristics, and due to the fact that these wells are often less instrumented compared to conventional oil wells. With different reservoir characteristics the system and methods available for conventional oil wells are not applicable in shale gas wells or in general unconventional reservoirs.